1. Field of the Disclosure
Embodiments disclosed herein relate generally to separation of components of a cuttings slurry. In a more specific aspect, embodiments disclosed herein relate to an apparatus for the concurrent transport and separation of drill cuttings from a cuttings slurry. In yet further aspects, embodiments disclosed herein relate to a system and a process for handling, separating, and disposing of a cuttings slurry.
2. Background
Oilfield drilling fluid, also referred to as “drilling mud” or “returned drilling fluid,” serves multiple purposes in the industry. Examples of drilling fluids can include, but are not limited to, water-based and/or oil-based fluids that are circulated downhole to provide hydrostatic pressure during drilling operations, as well as remove cuttings during a drilling operation, cool and lubricate a drill bit. Typically, the fluid is mixed at the surface and pumped downhole at high pressure to the drill bit through a bore of the drillstring. Once the fluid reaches the drill bit, it exits through various nozzles and ports where it lubricates and cools the drill bit.
Drilling fluid provides a column of hydrostatic pressure, or head, to prevent “blow out” of the well being drilled. This hydrostatic pressure offsets formation pressures thereby preventing fluids from blowing out if pressurized deposits in the formation are breeched. Two factors contributing to the hydrostatic pressure of the drilling mud column are the height (or depth) of the column (i.e., the vertical distance from the surface to the bottom of the wellbore) itself and the density (or its inverse, specific gravity) of the fluid used. Depending on the type and construction of the formation to be drilled, various weighting and lubrication agents are mixed into the drilling mud to obtain the right mixture. Typically, drilling fluid weight is reported in “pounds,” short for pounds per gallon. Generally, increasing the amount of weighting agent solute dissolved in the mud base will create a heavier fluid. Drilling fluid that is too light may not protect the formation from blow outs, and drilling fluid that is too heavy may over invade the formation. Therefore, much time and consideration is spent to ensure the mud mixture is optimal. Because the mud evaluation and mixture process is time consuming and expensive, drillers and service companies prefer to reclaim the returned drilling fluid and recycle it for continued use.
Another significant purpose of the drilling mud is to carry the cuttings away from the drill bit at the bottom of the borehole to the surface. As a drill bit pulverizes or scrapes the rock formation at the bottom of the borehole, small pieces of solid material are left behind. The drilling fluid exiting the nozzles at the bit acts to stir-up and carry the solid particles of rock and formation to the surface within the annulus between the drillstring and the borehole. Therefore, the fluid exiting the borehole from the annulus is a slurry of formation cuttings in drilling fluid.
The exiting drilling fluids used in drilling operations return from downhole as a cuttings slurry, which typically will include both drilling fluid and drill cuttings. The composition of the cuttings slurry may also include other materials, such as weighting additives and agents, other suspended particulate matter, as well as other fluids. Before the fluid can be recycled and re-pumped down through nozzles of the drill bit, the drill cutting must be separated.
After various separatory operations, the cuttings slurry can have a general liquid phase or a substantially solids phase further having “dry” or “wet” solids. Those of ordinary skill in the art will appreciate that “dry” or “wet” refers generally to the amount of drilling fluids remaining with the substantially solids phase during and/or after any separatory operation. Thus, the solids phase may be considered “wet” if a substantial quantity of fluid phase is still present after the separatory operation. Likewise, the solids phase may be considered “dry” if the cuttings do not contain a substantial quantity of fluid phase. Those of ordinary skill in the art will further appreciate that the amount of fluids remaining with either of the phases may vary according to the type of formation being drilled, the type of drilling fluids used in the drilling operation, and the type of separatory operation employed.
Separation operations such as a clarifier, a centrifuge, a screen, a mud cleaner, or a shaker, are well known in the art for removing drilling fluid from a cuttings slurry. However, these operations are not always capable of sufficient or adequate separation of drilling fluids from the cuttings slurry. For example, a cuttings slurry recovered from a shaker may have a reduced drilling fluids content as high as 50% by volume. The high volume of drilling fluid in a cuttings slurry is problematic because at the end-point in a process, this slurry is usually designated for disposal. The effect of losing drilling fluid through disposal is doubled because replacement drilling fluid is subsequently re-added as a make-up stream. Further, the added liquid weight remaining in the cuttings slurry creates a greater load requirement for transport and disposal operations.
Accordingly, there exists a need in the art for improved separation devices and/or processes for removing drilling fluid from drill cuttings.